U.S. patent number 9,160,158 [Application Number 14/052,449] was granted by the patent office on 2015-10-13 for coordinated high-impedance fault detection systems and methods.
This patent grant is currently assigned to Schweitzer Engineering Laboratories, Inc.. The grantee listed for this patent is Schweitzer Engineering Laboratories, Inc.. Invention is credited to Daqing Hou, Mangapathirao Venkata Mynam, Edmund O. Schweitzer, III.
United States Patent |
9,160,158 |
Schweitzer, III , et
al. |
October 13, 2015 |
Coordinated high-impedance fault detection systems and methods
Abstract
Systems and methods are presented for detecting high-impedance
faults (HIFs) in an electric power delivery system using a
plurality of coordinated high-impedance fault detection systems. In
certain embodiments, a method for HIFs may include receiving first
and second current representations associated with first and second
locations of the electric power delivery system respectively. Based
on at least one of the first and second current representations,
the occurrence of an HIF may be determined. A relative location of
the HIF may be determined based on a relative amount of
interharmonic content associated with an HIF included in the first
and second current representations, and a protective action may be
taken based on the determined relative location.
Inventors: |
Schweitzer, III; Edmund O.
(Pullman, WA), Mynam; Mangapathirao Venkata (Pullman,
WA), Hou; Daqing (Des Moines, WA) |
Applicant: |
Name |
City |
State |
Country |
Type |
Schweitzer Engineering Laboratories, Inc. |
Pullman |
WA |
US |
|
|
Assignee: |
Schweitzer Engineering
Laboratories, Inc. (Pullman, WA)
|
Family
ID: |
50475112 |
Appl.
No.: |
14/052,449 |
Filed: |
October 11, 2013 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20140104738 A1 |
Apr 17, 2014 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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61713392 |
Oct 12, 2012 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
H02H
3/52 (20130101); H02H 3/08 (20130101); H02H
7/261 (20130101) |
Current International
Class: |
H02H
3/08 (20060101); H02H 3/52 (20060101); H02H
7/26 (20060101) |
Field of
Search: |
;361/42 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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0307826 |
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Mar 1992 |
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EP |
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0122104 |
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Mar 2001 |
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WO |
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2006044354 |
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Apr 2006 |
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WO |
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Other References
PCT/US2013/064695, Patent Cooperation Treaty, International Search
Report and Written Opinion of the International Searching
Authority, Feb. 3, 2014. cited by applicant .
PCT/US2007/011603, Patent Cooperation Treaty, International Search
Report and Written Opinion of the International Searching
Authority, Feb. 14, 2008. cited by applicant .
PCT/US2007/011602, Patent Cooperation Treaty, International Search
Report and Written Opinion of the International Searching
Authority, Jul. 21, 2008. cited by applicant.
|
Primary Examiner: Bauer; Scott
Attorney, Agent or Firm: Davis; John P. Edge; Richard M.
Parent Case Text
RELATED APPLICATIONS
This application claims priority under 35 U.S.C. .sctn.119(e) to
U.S. Provisional Patent Application No. 61/713,392, filed Oct. 12,
2012, titled "Coordination of High-Impedance Fault Detection,"
which is hereby incorporated by reference in its entirety.
Claims
What is claimed is:
1. A method for detecting high-impedance faults in an electric
power delivery system comprising: receiving a first current
representation associated with a first location of the electric
power delivery system; receiving a second current representation
associated with a second location of the electric power delivery
system; determining, based on at least one of the first and second
current representations, the occurrence of a high-impedance fault
on the electric power delivery system; determining a relative
location of the high-impedance fault based, at least in part, on a
relative amount of signal content associated with a high-impedance
fault included in the first and second current representations;
coordinating a first protective action by one of a first
intelligent electronic device (IED) and a second IED based on the
determined relative location of the high-impedance fault, and
implementing the first protective action by one of the first IED
and the second IED based on the determined relative location.
2. The method of claim 1, wherein the first current representation
comprises a measurement by the first IED and the second current
representation comprises a measurement by the second IED.
3. The method of claim 1, wherein the first protective action
comprises issuing a control signal to electrically isolate a
portion of the electric power delivery system including the
high-impedance fault.
4. The method of claim 1, further comprising: determining the
relative location of the high-impedance fault comprises determining
that the high-impedance fault is located closer to the first
location than then second location; and wherein implementing the
first protective action comprises the first IED issuing a control
signal to electrically isolate a portion of the electric power
delivery system including the high-impedance fault.
5. The method of claim 1, wherein determining the occurrence of the
high-impedance fault comprises determining that at least one of the
first current representation and the second current representation
comprises signal content associated with a high-impedance
fault.
6. The method of claim 5, wherein determining that at least one of
the first current representation and the second current
representation comprises signal content associated with a
high-impedance fault comprises determining that at least one of the
first current representation and the second current representation
comprises signal content exceeding a detection threshold.
7. The method of claim 5, wherein determining that at least one of
the first current representation and the second current
representation comprises signal content associated with a
high-impedance fault further comprises determining that at least
one of the first current representation and the second current
representation comprises signal content exceeding the detection
threshold by a number of times in a particular period.
8. The method of claim 7, wherein the particular period is based on
a relative magnitude of the signal content.
9. The method of claim 5, wherein determining that at least one of
the first current representation and the second current
representation comprises signal content associated with a
high-impedance fault comprises adjusting at least one of the first
current representation and the second current representation by a
reference and determining that the adjusted information comprises
signal content exceeding a detection threshold.
10. The method of claim 9, wherein the reference comprises an
average level of signal content associated with normal system
noise.
11. The method of claim 10, wherein the detection threshold is
adjusted based on the reference.
12. The method of claim 1, wherein the method further comprises:
determining, based on at least one of the first and second current
representations, that a portion of the electric power delivery
system including the high-impedance fault has not been isolated
after implementing the first protective action; and implementing a
second protective action to isolate the high-impedance fault.
13. The method of claim 12, wherein the first protective action
comprises issuing a first control instruction to electrically
isolate a first portion of the electric power delivery system and
the second protective action comprises issuing a second control
instruction to electrically isolate a second portion of the
electric power delivery system.
14. An intelligent electronic device (IED) associated with an
electric power delivery system, the IED comprising: an interface
configured to receive first current representation associated with
a first location of the electric power delivery system and second
current representation associated with a second location of the
electric power delivery system; a processor communicatively coupled
to the interface; a computer-readable storage medium
communicatively coupled to the processor, the computer-readable
storage medium storing instructions that when executed by the
processor cause the processor to determine, based on at least one
of the first and second current representations, the occurrence of
a high-impedance fault on the electric power delivery system,
determine a relative location of the high-impedance fault based, at
least in part, on a relative amount of signal content associated
with a high-impedance fault included in the first and second
current representations, coordinating a first protective action by
one of a first intelligent electronic device (IED) and a second IED
based on the determined relative location of the high-impedance
fault, and implement the first protective action by one of the
first IED and the second IED based on the determined relative
location.
15. The IED of claim 14, wherein the first protective action
comprises issuing a control signal, via the interface, to
electrically isolate a portion of the electric power delivery
system including the high-impedance fault.
16. The IED of claim 14, wherein the first current representation
is received from a first IED and the second current representation
is received form a second IED and determining the relative location
of the high-impedance fault comprises determining that the
high-impedance fault is located closer to the first location than
then second location and implementing the first protective action
comprises instructing the first IED to issue a control signal to
trip a breaker to isolate a portion of the electric power delivery
system including the high-impedance fault.
17. The IED of claim 14, wherein determining the occurrence of the
high-impedance fault comprises determining that at least one of the
first current representation and the second current representation
comprises signal content associated with a high-impedance
fault.
18. The IED of claim 17, wherein determining that at least one of
the first current representation and the second current
representation comprises signal content associated with a
high-impedance fault comprises determining that at least one of the
first current representation and the second current representation
comprises signal content exceeding a detection threshold.
19. The IED of claim 18, wherein determining that at least one of
the first current representation and the second current
representation comprises signal content associated with a
high-impedance fault comprises adjusting at least one of the first
current representation and the second current representation by a
reference and determining that the adjusted information comprises
signal content exceeding a detection threshold.
20. The IED of claim 14, wherein computer-readable medium further
stores instructions configured to cause the processor to determine,
based on at least one of the first and second current
representations, that a portion of the electric power delivery
system including the high-impedance fault has not been isolated
after implementing the first protective action and implement a
second protective action to isolate the high-impedance fault.
Description
TECHNICAL FIELD
This disclosure relates to systems and methods for detecting
high-impedance faults in an electric power delivery system and,
more particularly, to systems and methods for detecting
high-impedance faults in an electric power delivery using a
plurality of coordinated high-impedance fault detection
systems.
BRIEF DESCRIPTION OF THE DRAWINGS
Non-limiting and non-exhaustive embodiments of the disclosure are
described, including various embodiments of the disclosure, with
reference to the figures, in which:
FIG. 1 illustrates a simplified diagram of one embodiment of an
electric power delivery system that includes intelligent electronic
devices consistent with embodiments disclosed herein.
FIG. 2 illustrates a functional block diagram of a system for
detecting high-impedance faults consistent with embodiments
disclosed herein.
FIG. 3 is a graph illustrating adaptive tuning that may be used in
high-impedance fault detection consistent with embodiments
disclosed herein.
FIG. 4 illustrates a simplified one-line diagram of an electric
power delivery system consistent with embodiments disclosed
herein.
FIG. 5 illustrates a simplified one-line diagram of an electric
power delivery system experiencing a high-impedance fault
consistent with embodiments disclosed herein.
FIG. 6 illustrates exemplary current signals associated with a
high-impedance fault at two points in an electric power delivery
system consistent with embodiments disclosed herein.
FIG. 7 illustrates exemplary interharmonic current signals
associated with a high-impedance fault at two points in an electric
power delivery system consistent with embodiments disclosed
herein.
FIG. 8 illustrates an exemplary interharmonic ratio signal
associated with a high-impedance fault at two points in an electric
power delivery system consistent with embodiments disclosed
herein.
FIG. 9 illustrates a flow chart of a method for monitoring and
protecting an electric power delivery system consistent with
embodiments disclosed herein.
FIG. 10 illustrates a functional block diagram of an intelligent
electronic device consistent with embodiments disclosed herein.
DETAILED DESCRIPTION
The embodiments of the disclosure will be best understood by
reference to the drawings. It will be readily understood that the
components of the disclosed embodiments, as generally described and
illustrated in the figures herein, could be arranged and designed
in a wide variety of different configurations. Thus, the following
detailed description of the embodiments of the systems and methods
of the disclosure is not intended to limit the scope of the
disclosure, as claimed, but is merely representative of possible
embodiments of the disclosure. In addition, the steps of a method
do not necessarily need to be executed in any specific order, or
even sequentially, nor do the steps need be executed only once,
unless otherwise specified.
In some cases, well-known features, structures, or operations are
not shown or described in detail. Furthermore, the described
features, structures, or operations may be combined in any suitable
manner in one or more embodiments. It will also be readily
understood that the components of the embodiments, as generally
described and illustrated in the figures herein, could be arranged
and designed in a wide variety of different configurations. For
example, throughout this specification, any reference to "one
embodiment," "an embodiment," or "the embodiment" means that a
particular feature, structure, or characteristic described in
connection with that embodiment is included in at least one
embodiment. Thus, the quoted phrases, or variations thereof, as
recited throughout this specification are not necessarily all
referring to the same embodiment.
Several aspects of the embodiments described are illustrated as
software modules or components. As used herein, a software module
or component may include any type of computer instruction or
computer executable code located within a memory device that is
operable in conjunction with appropriate hardware to implement the
programmed instructions. A software module or component may, for
instance, comprise one or more physical or logical blocks of
computer instructions, which may be organized as a routine,
program, object, component, data structure, etc., that performs one
or more tasks or implements particular abstract data types.
In certain embodiments, a particular software module or component
may comprise disparate instructions stored in different locations
of a memory device, which together implement the described
functionality of the module. Indeed, a module or component may
comprise a single instruction or many instructions, and may be
distributed over several different code segments, among different
programs, and across several memory devices. Some embodiments may
be practiced in a distributed computing environment where tasks are
performed by a remote processing device linked through a
communications network. In a distributed computing environment,
software modules or components may be located in local and/or
remote memory storage devices. In addition, data being tied or
rendered together in a database record may be resident in the same
memory device, or across several memory devices, and may be linked
together in fields of a record in a database across a network.
Embodiments may be provided as a computer program product including
a non-transitory machine-readable medium having stored thereon
instructions that may be used to program a computer or other
electronic device to perform processes described herein. The
non-transitory machine-readable medium may include, but is not
limited to, hard drives, floppy diskettes, optical disks, CD-ROMs,
DVD-ROMs, ROMs, RAMs, EPROMs, EEPROMs, magnetic or optical cards,
solid-state memory devices, or other types of
media/machine-readable medium suitable for storing electronic
instructions. In some embodiments, the computer or other electronic
device may include a processing device such as a microprocessor,
microcontroller, logic circuitry, or the like. The processing
device may further include one or more special purpose processing
devices such as an application specific interface circuit (ASIC),
PAL, PLA, PLD, field programmable gate array (FPGA), or any other
customizable or programmable device.
Electrical power generation and delivery systems are designed to
generate, transmit, and distribute electrical energy to loads.
Electrical power generation and delivery systems may include a
variety of equipment, such as electrical generators, electrical
motors, power transformers, power transmission and distribution
lines, circuit breakers, switches, buses, transmission and/or
feeder lines, voltage regulators, capacitor banks, and the like.
Such equipment may be monitored, controlled, automated, and/or
protected using intelligent electronic devices (IEDs) that receive
electric power system information from the equipment, make
decisions based on the information, and provide monitoring,
control, protection, and/or automation outputs to the
equipment.
In some embodiments, an IED may include, for example, remote
terminal units, differential relays, distance relays, directional
relays, feeder relays, overcurrent relays, voltage regulator
controls, voltage relays, breaker failure relays, generator relays,
motor relays, automation controllers, bay controllers, meters,
recloser controls, communication processors, computing platforms,
programmable logic controllers (PLCs), programmable automation
controllers, input and output modules, governors, exciters, statcom
controllers, static var compensator (SVC), on-load tap-changer
(OLTC) controllers, and the like. Further, in some embodiments,
IEDs may be communicatively connected via a network that includes,
for example, multiplexers, routers, hubs, gateways, firewalls,
and/or switches to facilitate communications on the networks, each
of which may also function as an IED. Networking and communication
devices may also be integrated into an IED and/or be in
communication with an IED. As used herein, an IED may include a
single discrete IED or a system of multiple IEDs operating
together.
Electrical power delivery system equipment may be monitored and
protected from various malfunctions and/or conditions using one or
more IEDs. For example, an IED may be configured to detect and
protect the electrical power system equipment from abnormal
conditions, such as high-impedance fault (HIF) events. HIF events
may occur, for example, on a distribution feeder line of an
electric power delivery system due to a variety of conditions. For
example, downed feeder lines, intrusion onto a line (e.g., as may
occur when a tree or other object contacts the line), and/or the
like may cause HIF events.
HIF events may pose a safety risk and/or damage an electrical power
delivery system and/or its constituent components. Accordingly,
detecting HIF events and implementing one or more suitable
protective actions (e.g., disconnecting a portion of an electrical
power delivery system experiencing an HIF) may mitigate potential
harm caused by damage an electrical power delivery system. HIF
event detection may utilize a variety of techniques and/or
algorithms, including the techniques detailed in U.S. Pat. Nos.
7,720,619 and 7,945,400, both assigned to Schweitzer Engineering
Laboratories, Inc. and incorporated herein by reference in their
entireties. In certain circumstances, HIF events may be difficult
to detect because HIF events may not introduce overcurrent
conditions sufficient to trigger a detection element of a
protective IED.
IEDs monitoring a portion of an electrical power delivery system
located nearer to an HIF may be better able to detect the HIF event
due to their proximity to the fault. For example, an IED monitoring
a portion of an electrical power delivery system located nearer to
an HIF may observe relatively larger overcurrent and/or
interharmonic and/or other signals associated with the fault
condition than an IED monitoring a portion of the system located
further from the fault. In certain embodiments, an interharmonic
may comprise signals with frequencies that are not integer
multiples of a fundamental frequency of the electric power delivery
system. For example, in North America, the fundamental frequency of
typical electric power delivery systems is 60 Hz. Accordingly,
harmonic frequencies in such systems include 120 Hz, 180 Hz, 240
Hz, etc. Interharmonic frequencies are those frequencies other than
harmonic frequencies and/or fundamental frequencies.
Consistent with embodiments disclosed herein, a plurality of IEDs
may be utilized in connection with HIF event detection to more
accurately detect HIF events and implement suitable protective
actions to mitigate potentially unsafe conditions and damage to the
electrical power delivery system. In certain embodiments, utilizing
a plurality of IEDs to detect HIF events may allow for a more
accurate determination of a location of the HIF event.
FIG. 1 illustrates a simplified diagram of an electric power
generation and delivery system 100 that includes IEDs 102-108
consistent with embodiments disclosed herein. Although illustrated
as a one-line diagram for purposes of simplicity, electrical power
generation and delivery system 100 may also be configured as a
three phase power system. Moreover, embodiments disclosed herein
may be utilized by any electric power generation and delivery
system and is therefore not limited to the specific system 100
illustrated in FIG. 1. Accordingly, embodiments may be integrated,
for example, in industrial plant power generation and delivery
systems, deep-water vessel power generation and delivery systems,
ship power generation and delivery systems, distributed generation
power generation and delivery systems, and utility electric power
generation and delivery systems.
The electric power generation and delivery system 100 may include
generation, transmission, distribution, and power consumption
equipment. For example, the system 100 may include one or more
generators 110-116 that, in some embodiments, may be operated by a
utility provider for generation of electrical power for the system
100. Generators 110 and 112 may be coupled to a first transmission
bus 118 via step up transformers 120 and 122, which are
respectively configured to step up the voltages provided to first
transmission bus 118. A transmission line 124 may be coupled
between the first transmission bus 118 and a second transmission
bus 126. Another generator 114 may be coupled to the second
transmission bus 126 via step up transformer 128 which is
configured to step up the voltage provided to the second
transmission bus 126.
A step down transformer 130 may be coupled between the second
transmission bus 126 and a distribution bus 132 configured to step
down the voltage provided by the second transmission bus 126 at
transmission levels to lower distribution levels at the
distribution bus 132. One or more feeders 134, 136 may draw power
from the distribution bus 132. The feeders 134, 136 may distribute
electric power to one or more loads 138, 140. In some embodiments,
the electric power delivered to the loads 138, 140 may be further
stepped down from distribution levels to load levels via step down
transformers 142 and 144, respectively.
Feeder 134 may feed electric power from the distribution bus 132 to
a distribution site 146 (e.g., a refinery, smelter, paper
production mill, or the like). Feeder 134 may be coupled to a
distribution site bus 148. The distribution site 146 may also
include a distributed generator 116 configured to provide power to
the distribution site bus 148 at an appropriate level via
transformer 150. The distribution site 146 may further include one
or more loads 138. In some embodiments, the power provided to the
loads 138 from the distribution site bus 148 may be stepped up or
stepped down to an appropriate level via transformer 142. In
certain embodiments, the distribution site 146 may be capable of
providing sufficient power to loads 138 independently by the
distributed generator 116, may utilize power from generators
110-114, or my utilize both the distributed generator 116 and one
or more of generators 110-114 to provide electric power to the
loads.
IEDs 102-108 may be configured to control, monitor, protect, and/or
automate the electric power system 100. As used herein, an IED may
refer to any microprocessor-based device that monitors, controls,
automates, and/or protects monitored equipment within an electric
power system. In some embodiments, IEDs 102-108 may gather status
information from one or more pieces of monitored equipment.
Further, IEDs 102-108 may receive information concerning monitored
equipment using sensors, transducers, actuators, and the like.
Although FIG. 1 illustrates separate IEDs monitoring a signal
(e.g., IED 104) and controlling a breaker (e.g., IED 108), these
capabilities may be combined into a single IED.
FIG. 1 illustrates various IEDs 102-108 performing various
functions for illustrative purposes and does not imply any specific
arrangements or functions required of any particular IED. In some
embodiments, IEDs 102-108 may be configured to monitor and
communicate information, such as voltages, currents, equipment
status, temperature, frequency, pressure, density, infrared
absorption, radio-frequency information, partial pressures,
viscosity, speed, rotational velocity, mass, switch status, valve
status, circuit breaker status, tap status, meter readings, and the
like. For example, IEDs 102-108 may be configured to monitor and
communicate information relating to overcurrent and/or
interharmonic and/or other signal conditions of a monitored line
(e.g., a feeder and/or transmission line). Further, IEDs 102-108
may be configured to communicate calculations, such as phasors
(which may or may not be synchronized as synchrophasors), events,
fault distances, differentials, impedances, reactances, frequency,
and the like. IEDs 102-108 may also communicate settings
information, IED identification information, communications
information, status information, alarm information, and the like.
Information of the types listed above, or more generally,
information about the status of monitored equipment, may be
generally referred to herein as monitored system data.
In certain embodiments, IEDs 102-108 may issue control instructions
to the monitored equipment in order to control various aspects
relating to the monitored equipment. For example, an IED (e.g., IED
106) may be in communication with a circuit breaker (e.g., breaker
152), and may be capable of sending an instruction to open and/or
close the circuit breaker, thus connecting or disconnecting a
portion of a power system. In another example, an IED may be in
communication with a recloser and capable of controlling reclosing
operations. In another example, an IED may be in communication with
a voltage regulator and capable of instructing the voltage
regulator to tap up and/or down. Information of the types listed
above, or more generally, information or instructions directing an
IED or other device to perform a certain action, may be generally
referred to as control instructions.
The distributed site 146 may include an IED 108 for monitoring,
controlling, and protecting the equipment of the distributed site
146 (e.g., generator 116, transformer 142, etc.). IED 108 may
receive monitored system data, including current signals via
current transformer (CT) 154 and voltage signals via potential
transformer (PT 156) from one or more locations (e.g., line 158) in
the distribution site 146. The IED 108 may further be in
communication with a breaker 160 coupled between the feeder 134 and
the distribution site bus 148. In certain embodiments, the IED 108
may be configurable to cause the breaker 160 to disconnect the
distribution site bus 148 from the distribution bus 132, based on
monitored system data received via CT 154 and PT 156.
Feeder 136 may be communicatively coupled with an IED 106. The IED
106 may be configured to control a breaker 152 between the loads
140 and the distribution bus 132 based on monitored system data. In
some embodiments, the power provided to the loads 140 from the
distribution bus 132 may be stepped up or stepped down to an
appropriate level via transformer 144. Like the IED 108 of the
distribution site 146, monitored system data may be obtained by IED
106 using CTs and/or PTs (not shown).
Other IEDs (e.g., IED 104) may be configured to monitor, control,
and/or protect the electric power generation and delivery system
100. For example IED 104 may provide transformer and generator
protection to the step-up transformer 120 and generator 110. In
some embodiments, IEDs 104-108 may be in communication with another
IED 102, which may be a central controller, synchrophasor vector
processor, automation controller, programmable logic controller
(PLC), real-time automation controller, Supervisory Control and
Data Acquisition (SCADA) system, or the like. For example, in some
embodiments, IED 102 may be a synchrophasor vector processor, as
described in U.S. Patent Application Publication No. 2009/0088990,
which is incorporated herein by reference in its entirety. In other
embodiments, IED 102 may be a real-time automation controller, such
as is described in U.S. Patent Application Publication No.
2009/0254655, which is incorporated herein by reference in its
entirety. IED 102 may also be a PLC or any similar device capable
of receiving communications from other IEDs and processing the
communications there from. In certain embodiments, IEDs 104-108 may
communicate with IED 102 directly or via a communications network
(e.g., network 162).
The central IED 102 may communicate with other IEDs 104-108 to
provide control and monitoring of the other IEDs 104-108 and the
power generation and delivery system 100 as a whole. In some
embodiments, IEDs 104-108 may be configured to generate monitored
system data in the form of time-synchronized phasors
(synchrophasors) of monitored currents and/or voltages. In some
embodiments, synchrophasor measurements and communications may
comply with the IEC C37.118 protocol. In certain embodiments, IEDs
102-108 may receive common time signals for synchronizing collected
data (e.g., by applying time stamps for the like). Accordingly,
IEDs 102-108 may receive common time signals from time references
164-170 respectively. In some embodiments, the common time signals
may be provided using a Global Positioning System (GPS) satellite
(e.g., IRIG), a common radio signal such as WWV or WWVB, a network
time signal such as IEEE 1588, or the like.
Consistent with embodiments disclosed herein, IEDs 102-108 may be
configured to detect and/or identify one or more HIF events from
monitored system data. For example, IEDs 102-108 may be configured
to receive current information and/or measurements (e.g., current
measurements of a transmission and/or a feeder line) and, based on
the current information and/or measurements, detect and/or identify
HIF fault events. In certain embodiments, the HIF events may be
detected and/or identified when monitored current information
exhibits overcurrent conditions and/or associated interharmonic
and/or harmonic signals. For example, in some embodiments, IEDs
102-108 may be configured to determine when monitored current
signals include interharmonic signals associated with an HIF event
that exceed one or more thresholds (e.g., thresholds indicating an
HIF event). Based on a determination that the interharmonic signals
exceed the one or more thresholds, IEDs 102-108 may detect the
occurrence of an HIF event.
Although embodiments of the disclosed systems and methods are
described herein as utilizing interharmonic content in measured
current information to identify HIFs, in further embodiments, a
variety of other suitable signals and/or signal content may
alternatively and/or additionally be utilized. For example, in some
embodiments, odd harmonic content associated with HIF events may be
used to identify HIFs. Similarly, embodiments may utilize
incremental changes of root mean square (RMS) signal information to
identify HIFs.
In some embodiments, thresholds utilized to detect and/or identify
HIF events may be adaptively tuned to account for normal system
noise levels, thereby increasing the accuracy of HIF event
detection and/or identification. For example, as discussed in more
detail below, in some embodiments IEDs 102-108 may maintain a
dynamic reference over time of interharmonic signals included in
measured current signals. This long term reference may be utilized
as a threshold for differentiating interharmonic signals attributed
to normal system noise from interharmonic signals associated with
HIF events.
Consistent with embodiments disclosed herein, a plurality of IEDs
102-108 may be utilized to detect HIF events and implement suitable
protective actions to mitigate potentially unsafe conditions and
damage to the electrical power delivery system 100. For example, as
discussed above, an IED monitoring a portion of the electrical
power delivery system 100 located nearer to an HIF may be better
able to detect the fault event due to its proximity to the fault.
For example, IED 108 may be able to more accurately detect HIF
events associated with line 158 and/or the distribution site 146
than another remotely located IED (e.g., IED 104 and/or the like).
In certain embodiments, IEDs located nearer to an HIF may be better
able to detect the fault event due to higher interharmonic
signal-to-noise ratios associated with an HIF event closer to the
fault.
Detecting HIF events utilizing a plurality of IEDs may allow for
determination of fault localization information relating to the HIF
event. Based on relative signal-to-noise ratios associated with an
HIF event, the locations of one or more IEDs 102-108 relative to a
fault may be determined. For example, if interharmonic
signal-to-noise ratios associated with an HIF event measured by a
first IED are relatively higher than interharmonic signal-to-noise
ratios associated with an HIF event measured by a second IED, it
may be determined that the HIF is located nearer to the first
IED.
Utilizing a plurality of IEDs 102-108 in the detection of HIF
events may allow for prioritized implementation of protective
actions by IEDs 102-108. For example, an IED located closer to a
fault event may implement certain protective actions (e.g.,
tripping a breaker or the like) before other IEDs implement
protective actions. In certain instances, if such a prioritized
protective action resolves an HIF condition, further protective
actions may not be necessary. If, however, the HIF condition is not
resolved, additional protective may be implemented by the IED
and/or other IEDs. Prioritized protective actions may be
coordinated by IEDs 102-108 based on coordinated instructions
exchanged therebetween. Alternatively or in addition, prioritized
protective actions may be coordinated by a central IED 102. For
example, based on monitored current information and/or detected HIF
events at IEDs 104-108, central IED 102 may identify an IED of IEDs
104-108 located nearer to the fault and instruct the IED to
implement one or more suitable protective actions.
FIG. 2 illustrates a functional block diagram of a system 200 for
detecting HIF events consistent with embodiments disclosed herein.
In certain embodiments, the system 200 may comprise an IED system
configured to, among other things, detect HIF events and implement
suitable protective actions in response. Components 202-212 of
system 200 may be implemented in an IED using hardware, software,
firmware, and/or any combination thereof. As illustrated, a current
signal 214 may be received as an input to an interharmonic
extraction module 202. The current signal 214 may be generated by,
for example, a current transformer and/or other associated current
measurement device associated with the system 200, and may provide
an indication of current flow at a particular location of an
electric power delivery system monitored by system 200 (e.g., a
location on a feeder line, a transmission line, etc.).
The interharmonic extraction module 202 may extract interharmonic
content 216 included in the received current signal 214.
Interharmonic content 216 extracted by the interharmonic extraction
module 202 over time may be provided to a reference module 204.
Based on interharmonic content 216 provided to the reference module
204 over time, the reference module 204 may generate and/or store a
dynamically updated reference and/or indication of an amount of
interharmonic content (e.g., an average amount) of the received
current signal 214 over time. In certain embodiments, this dynamic
reference and/or indication may represent an average interharmonic
content of received current signals 214 over time associated with
normal system noise (e.g., interharmonic signal levels under normal
load conditions), and may be utilized in differentiating
interharmonic signals attributed to HIF events from interharmonic
signals associated with normal system noise.
Difference module 208 may be provided the reference generated by
the reference module 204 and the instantaneous extracted
interharmonic content signal 216 as inputs, and may calculate a
difference between the reference and the instantaneous extracted
interharmonic content signal 216. This calculated difference may be
indicative of an amount that the instantaneous extracted
interharmonic content signal 216 varies from normal system noise
levels.
The calculated difference may be provided to an interharmonic
activity counting module 210. The interharmonic activity counting
module 210 may count a number of occurrences of the difference
calculated by the difference module 208 exceeding a defined
threshold. In certain embodiments, the defined threshold may be
provided by a detection threshold tuning module 206. The threshold
maintained and/or provided by the detection threshold tuning module
206 to the interharmonic activity counting module 210 may be
calculated by the detection threshold tuning module 206 based on
the reference generated by the reference module 204 and/or
interharmonic activity information 218 generated by the
interharmonic activity counting module 210. Based on this
information, the threshold maintained and/or provided by the
detection threshold tuning module 206 may be dynamically updated
over time.
A number of occurrences of the threshold being exceeded as well as
magnitudes of the occurrences may be provided to interharmonic
decision logic 212. Based on the magnitudes and the number and/or
rates of occurrences of the interharmonic threshold being exceeded,
the interharmonic decision logic 212 may identify the occurrence of
an HIF event. In response, the interharmonic decision logic 212 may
generate an alarm signal 222 and/or a fault signal 220. Based on
these signals, system 200 and/or an associated IED or system may
implement a suitable protective action (e.g., tripping a breaker to
isolate a fault) to mitigate potentially unsafe conditions caused
by an HIF event.
FIG. 3 is a graph 300 illustrating adaptive tuning used in HIF
detection consistent with embodiments disclosed herein.
Particularly, the graph 300 illustrates adjustment of HIF detection
thresholds 302 based on changes to instantaneous interharmonic
content in measured current signals over time. As illustrated, an
average of interharmonic content 304 over time of the current
signal may be maintained. In certain embodiments, the average over
time 304 may be associated with normal system interharmonic noise.
An HIF detection threshold 302 may be updated as the average
interharmonic content 304 of the signal changes. For example, as
illustrated, when the average interharmonic content 304 increases,
the HIF detection threshold 302 may also increase.
In certain embodiments, HIF detection logic may identify an HIF
event when interharmonic content exceeds the detection threshold
302 by a certain amount and/or by a certain number of times in a
given period. For example, as illustrated, interharmonic content
during period 308 exceeds the detection threshold 302 frequently by
a large magnitude. Such behavior may be indicative of an HIF event,
and HIF detection logic may identify the event accordingly.
Inharmonic content during period 306, however, exceeds the
threshold 302 less frequently, which may not be indicative of an
HIF event. Accordingly, the HIF detection logic may not identify an
HIF event based on inharmonic activity during period 306.
In certain embodiments, a number of times and/or a duration of a
period during which interharmonic content exceeds detection
threshold 302 triggering an HIF event, may depend and/or be
adjusted based on a magnitude of the interharmonic content
exceeding the threshold 302. For example, if interharmonic content
exceeds the detection threshold 302 by a relatively large
magnitude, a number of threshold crossings and/or a detection
period used by HIF detection logic may be relatively small and/or
short. Similarly, if interharmonic content exceeds the threshold
302 by a relatively small magnitude, the number of threshold
crossings and/or the detection period used by HIF detection logic
may be relatively larger and/or long.
FIG. 4 illustrates a simplified one-line diagram of an electric
power delivery system consistent with embodiments disclosed herein.
As illustrated, a distribution bus 400 may be electrically coupled
to a distribution feeder line 402 having a plurality of feeder
lines 404-408 leading therefrom (e.g., feeder lines leading to one
or more loads or the like). IED 412 may monitor certain measured
parameters of a location of the feeder line 402 including, among
other things, a current flow through the feeder line at the
monitored location. For example, IED 412 may be associated with a
distribution substation location of an electric power delivery
system. IED 412 may be communicatively coupled with a breaker 410
that may be configured to disconnect a portion of the electric
power delivery system when actuated by IED 412 (e.g., in response
to IED 412 detecting an HIF event or the like). IED 414 may
similarly monitor measured parameters (e.g., current) of another
location of the feeder line 402 and be configured to actuate (e.g.,
trip) a communicatively coupled breaker 416 upon detecting an HIF
event.
FIG. 5 illustrates a simplified one-line diagram of an electric
power delivery system experiencing an HIF 500 consistent with
embodiments disclosed herein. As illustrated, an HIF 500 may occur
on the distribution feeder line 402 due to a variety of conditions
(e.g., when tree or other object contacts the line and/or when a
conductor contacts the ground). IEDs 412, 414 may monitor
interharmonic content of measured current signals on the
distribution feeder line 402. Based on the monitored interharmonic
content, IEDs 412, 414 may identify the occurrence of the HIF event
500 on the distribution feeder line 402 and take one or more
suitable protective action to mitigate potentially unsafe
conditions and damage to the electric power delivery system. For
example, upon detecting the occurrence of the HIF event 500, IED
414 may trip breaker 416, thereby isolating the HIF 500 from the
electric power delivery system due to IED 414 monitoring a location
further away from the distribution bus 400 than IED 412.
FIG. 6 illustrates exemplary current signals 600, 602 associated
with an HIF event 500 and an associated simplified one-line diagram
of an electric power delivery system consistent with embodiments
disclosed herein. Current signal 600 may represent a current over
time measured by IED 412 and current signal 602 may represent a
current over time measured by IED 414. As illustrated, current
signal 602 measured by IED 414 may be lower than current signal 600
measured by IED 412. For example, due to a plurality of feeder
lines being located between the locations monitored by IEDs 412 and
414, the load current measured by IED 414 (e.g., an IED associated
with a recloser) may be lower than the load current measured by IED
412 (e.g., an IED associated with a distribution substation).
An HIF 500 may occur on the distribution feeder line 402 at a time
604. As illustrated, the HIF event 500 may introduce additional
fault current 606, 608 to the current signals 600, 602. Relative to
normal system current and noise 610, 612 preceding time 604
corresponding to the HIF event 500, fault current 608 measured by
IED 414 may be larger relative to system current and noise 612 than
fault current 606 measured by IED 412 due to the proximity of IED
414 to the HIF event 500 relative to IED 412. That is, fault
current signal-to-load ratios measured by IED 414 may be higher
than that measured by IED 412 due to its relative proximity to the
HIF event 500 and due to the lower current carried by distribution
feeder line 402 at the point monitored by IED 414. For example, the
magnitude of fault current 608 measured by IED 414 is larger than
the system current and noise 612 relative to the magnitude of fault
current content 606 measured by IED 412. Accordingly, IED 414 may
more accurately detect the HIF event 500 based on fault current
and/or interharmonic content 608 than IED 412. Moreover, there is a
relatively high current increase measured by IED 414 than IED 412
following the HIF event 500. In certain embodiments, this may also
allow IED 414 to detect the HIF event 500 more quickly than IED
412.
In certain embodiments, relative magnitudes of instantaneous fault
current 606, 608 and/or signal-to-noise ratios of fault current
606, 608 relative to system noise 610, 612 may be utilized to
determine a location of a fault relative to IEDs 412, 414. For
example, as illustrated, relative magnitudes of fault current 606,
608 and signal-to-noise ratios of instantaneous fault current 606,
608 relative to system current and noise 610, 612 measured by IED
414 are higher than those measured by IED 412. Accordingly, it may
be determined that the location of the electric power delivery
system monitored by IED 414 is closer to the HIF event 500 than the
location monitored by IED 412. In certain embodiments, fault
location information may be stored by IEDs 412, 414 and/or another
IED communicatively coupled therebetween.
In certain embodiments, fault location information may be utilized
in coordinating one or more protective actions implemented by IEDs
412, 414 and/or other IEDs to mitigate potentially unsafe
conditions and damage to the electric power delivery system.
Protective actions may be prioritized based on a location of an IED
relative to an HIF event 500. For example, based on a determination
that IED 414 is located nearer to HIF event 500 than IED 412, IED
414 may implement a protective action to mitigate unsafe conditions
caused by the HIF event 500. In certain embodiments, the protective
action may include tripping a breaker 416, thereby disconnecting
the HIF 500 from the electric power delivery system. If such a
prioritized protective action effectively resolves the HIF 500
(i.e., if IED 412 no longer detects an HIF after the protective
action), additional protective actions may not need be implemented.
If, however, the HIF condition is not resolved, additional
protective actions may be implemented and/or other IEDs (e.g., IED
412 may trip breaker 410). Moreover, coordination of such
protective actions may also provide additional redundancy, such
that if one proactive action fails to resolve the HIF 500,
additional protective actions may be implemented until the HIF 500
is resolved.
FIG. 7 illustrates signals 700, 702 associated with an HIF event
500 and an associated simplified one-line diagram of an electric
power delivery system consistent with embodiments disclosed herein.
Signal 700 may represent a difference between an interharmonic
current and an interharmonic current reference over time measured
by IED 412 and signal 702 may represent a difference between an
interharmonic current and an interharmonic current reference
current over time, as measured by IED 414. At time 604, an HIF 500
may occur on the distribution feeder line 402. The HIF 500 may
introduce interharmonic content associated with the fault into
current signals along the line 402. Accordingly, signals 700, 702
may include increased interharmonic content 706, 708 following the
HIF event 500 due to interharmonic content introduced by the fault
that is larger than average interharmonic content associated with
system noise.
In certain embodiments, a number of times the signals 700, 702
exceed one or more thresholds 710, 712 may be counted. In addition,
a magnitude of the signals 700, 702 when the signals 700, 702 cross
the thresholds 710, 712 may be recorded. This information may be
utilized, at least in part, in detecting the occurrence of an HIF
event 500, determining a relative location of the event 500, and/or
in implementing one or more protective actions in connection with
the same. As illustrated, because IED 414 is located nearer to the
HIF event 500, the magnitude of the interharmonic content 708 may
be relatively larger than interharmonic content 706. Accordingly,
IED 414 may more accurately and/or quickly detect the HIF event 500
than IED 412 and may implement one or more initial coordinated
protective actions in response.
In some embodiments, thresholds 710, 712 utilized to detect and/or
identify HIF event 500 may be adaptively tuned to account for
normal system noise levels, thereby increasing the accuracy of HIF
event detection and/or identification. For example, in some
embodiments IEDs 412, 414 may maintain a dynamic reference over
time of interharmonic signals included in measured current signals.
This long term reference may be utilized as a threshold for
differentiating interharmonic signals attributed to normal system
noise from interharmonic signals 706, 708 associated with HIF
events (e.g., HIF event 500).
FIG. 8 illustrates exemplary interharmonic measurement signals 800,
802 associated with an HIF 500 and an associated simplified
one-line diagram of an electric power delivery system consistent
with embodiments disclosed herein. Particularly, signal 800
indicates a number of times and associated ratio magnitudes 804 of
interharmonic content measured by IED 412 crossing a detection
threshold. Similarly, signal 802 indicates a number of times and
associated ratio magnitudes of interharmonic content 806 measured
by IED 414 crossing a detection threshold.
Signal 800 may represent a difference between an instantaneous
measured interharmonic current and an interharmonic current
reference over time measured by IED 412 and signal 802 may
represent a difference between an instantaneous measured
interharmonic current and an interharmonic current reference over
time measured by IED 414. At time 604, an HIF 500 may occur on the
distribution feeder line 402. The HIF 500 may introduce
interharmonic content associated with the fault into current
signals along the line 402. Accordingly, signals 800, 802 may
include increased interharmonic content 804, 806 following the HIF
event 500 due to measured instantaneous interharmonic content
introduced by the fault that is larger than the reference
interharmonic current associated with system noise. As illustrated,
because IED 414 is located nearer to the HIF event 500, the number
of times and ratio magnitudes of interharmonic content 806 crossing
a detection threshold may both be larger than the same measurements
made by IED 412. Accordingly, IED 414 may detect the HIF event 500
more accurately and/or quickly than IED 412 and may implement one
or more initial coordinated protective actions in response.
FIG. 9 illustrates a flow chart of a method 900 for monitoring and
protecting an electric power delivery system consistent with
embodiments disclosed herein. In certain embodiments, method 900
may be performed by a central IED communicatively coupled with a
first IED and a second IED. Among other things, the central IED may
be configured to coordinate detection of HIF events with the first
and second IEDs and to implement one or more prioritize protective
actions by at least the first IED and the second IED in response to
the same. In further embodiments, the first IED or the second IED
may perform the functions described with respect to the central
IED, together with the functions described with respect to either
the first IED or the second IED. Still further, various embodiments
may implement a variety of other distributed control schemes
consistent with the present disclosure.
At 902, the central IED may receive a first current representation
from the first IED and second current representation from the
second IED. In certain embodiments, the first current
representation may be associated with a first location of an
electrical power delivery system monitored by the first IED, and
the second current representation may be related to a location
associated with a second location of the electrical power delivery
system monitored by the second IED.
Based on at least one of the first and second current
representations, an HIF may be detected at 904. In certain
embodiments, an HIF may be detected when interharmonic content
exceeding one or more detection thresholds associated with an HIF
event is observed in the first and/or second current
representation. In some embodiments, an HIF may be detected when
the interharmonic content exceeds the detection thresholds by a
certain magnitude and/or exceeds the detection thresholds a
particular number of times in a given period. In certain
embodiments, the one or more detection thresholds may be
dynamically adjusted based on previously received current
information to more accurately identify the occurrence of HIF
events. Previously received current information may include an
average current flow over a period of time, trends based on a time
of day, information regarding factors that affect loading (e.g.,
weather conditions, connection/disconnection of large loads, etc.).
In some embodiments, interharmonic content associated with HIF
faults may be extracted from the first and second current
representations by subtracting average interharmonics over time
(e.g., interharmonics associated with normal system noise) from
instantaneous interharmonics included in the current
information.
At 906, a location of the HIF relative to the first location
monitored by the first IED and the second location monitored by the
second IED may be determined. In certain embodiments, based on
relative signal-to-noise ratios of interharmonic content associated
with ah HIF event included in the first current representation and
the second current representation, a location of the HIF relative
to the first and the second locations may be determined. For
example, if the relative signal-to-noise ratios and/or magnitudes
of interharmonic content associated with an HIF included in the
second current representation is higher than that included in the
first current representation, it may be determined that the second
location monitored by the second IED is closer to the HIF than the
first location monitored by the first IED.
At 908, a first protective action may be implemented by the first
IED and/or the second IED based on the relative location of the HIF
determined at 906. In certain embodiments, protective actions may
be prioritized based on a location of an IED relative to an HIF.
For example, based on a determination at 906 that the second IED is
located nearer to an HIF than the first IED, the second IED may
implement a first protective action to mitigate potentially unsafe
conditions caused by damage to the electrical power delivery system
caused by the HIF event. In certain embodiments, the protective
action may include tripping a breaker, thereby disconnecting and/or
isolating the HIF from the electric power delivery system.
At 910, a determination may be made as to whether the first
protective action successfully isolated the HIF. For example, a
determination may be made whether the first current information
measured by the first IED contains interharmonics associated with
an HIF after implementation of the first protective action. If the
first protective action successfully isolates the HIF from the
electric power delivery system, the method 900 may end. If,
however, the first protective action does not isolate the HIF from
the system, the method may proceed to 912 and a second protective
action may be implemented (e.g., tripping a second breaker by the
first and/or second IED).
FIG. 10 illustrates a block diagram of an IED 1000 consistent with
embodiments disclosed herein. Embodiments of the IED 1000 may be
utilized to implement embodiments of the systems and methods
disclosed herein. For example, the IED 1000 may be configured to
detect HIF events and implement one or more suitable protective
actions in response to the same. The IED 1000 may also be
configured to coordinate its actions and/or the actions one or more
other IEDs based, at least in part, on information provided by the
other IEDs.
IED 1000 may include a network interface 1002 configured to
communicate with a communication network. IED 1000 may also include
a time input 1004, which may be used to receive a time signal. In
certain embodiments, a common time reference may be received via
network interface 1002, and accordingly, a separate time input 1004
and/or Global Navigation Satellite System (GNSS) time input 1006
may not be necessary. One such embodiment may employ the IEEE 1588
protocol. Alternatively, a GNSS input 1006 may be provided in
addition to, or instead of, time input 1004.
A monitored equipment interface 1008 may be configured to receive
equipment status information from, and issue control instructions
to a piece of monitored equipment, such as an electrical generator,
breaker, voltage regulator controller, and/or the like. According
to certain embodiments, the monitored equipment interface 1008 may
be configured to interface with a variety of equipment of an
electric power delivery system. In certain embodiments, the
equipment status information and/or control instructions may be
communicated over the network interface 1002.
A computer-readable storage medium 1010 may be the repository of
one or more modules and/or executable instructions configured to
implement any of the processes described herein. A data bus 1012
may link monitored equipment interface 1008, time input 1004,
network interface 1002, GNSS time input 1006, and the
computer-readable storage medium 1010 to a processor 1014.
Processor 1014 may be configured to process communications received
via network interface 1002, time input 1004, GNSS time input 1006,
and/or monitored equipment interface 1008. Processor 1014 may
operate using any number of processing rates and architectures.
Processor 1014 may be configured to perform various algorithms and
calculations described herein using computer executable
instructions stored on computer-readable storage medium 1010.
Processor 1014 may be embodied as a general purpose integrated
circuit, an application specific integrated circuit, a
field-programmable gate array, and/or other programmable logic
devices.
In certain embodiments, IED 1000 may include a sensor component
1016. In the illustrated embodiment, sensor component 1016 is
configured to gather data from a location of the electric power
delivery system (not shown) using a current transformer 1018 and/or
a voltage transformer 1020. Voltage transformer 1020 may be
configured to step-down the power system's voltage (V) to a
secondary voltage waveform 1022 having a magnitude that can be
readily monitored and measured by IED 1000. Similarly, current
transformer 1018 may be configured to proportionally step-down the
power system's line current (I) to a secondary current waveform
1024 having a magnitude that can be readily monitored and measured
by IED 1000. Although not separately illustrated, the voltage and
current signals V and I may be secondary signals obtained from
equipment instruments designed to obtain signals from power system
equipment. For example, a secondary voltage signal V may be
obtained from a potential transformer (PT) in electrical
communication with a conductor. A secondary current signal I may be
obtained from a current transformer (CT) in electrical
communication with a conductor. Various other instruments may be
used to obtain signals from electric power delivery systems
including, for example, Rogowski coils, optical transformers, and
the like.
An analog-to-digital converter 1026 may multiplex, sample and/or
digitize the measured voltage and/or current signals to form
corresponding digitized current and voltage signals. Similar values
may also be received from other distributed controllers, station
controllers, regional controllers, or centralized controllers. The
values may be in a digital format or other format. In certain
embodiments, sensor component 1016 may be utilized to monitor
current signals associated with portion of an electric power
delivery system and/or detect interharmonic content associate with
HIF events included in such monitored current signals. Further,
sensor component 1016 may be configured to monitor a wide range of
characteristics associated with monitored equipment, including
equipment status, temperature, frequency, pressure, density,
infrared absorption, radio-frequency information, partial
pressures, viscosity, speed, rotational velocity, mass, switch
status, valve status, circuit breaker status, tap status, meter
readings, and the like.
A/D converter 1026 may be connected to processor 1014 by way of a
bus 1012, through which digitized representations of current and
voltage signals may be transmitted to processor 1014. As described
above, processor 1014 may be used to apply equipment status,
measurements, and derived values to an IED module. Processor 1014
may be used to detect the occurrence of HIF conditions and issue
control instructions in response to the same (e.g., instructions
implementing protective actions).
It should be noted that a separate device may be used in place of a
sensor component 1016 for providing signals from the electric power
delivery system to the IED 1000. Indeed, a separate device may be
configured to obtain signals from the electric power delivery
system (such as voltage and/or current signals), and create
digitized representations of the signals (for example current and
voltage signals), apply a time stamp, and/or supply such
information to the IED 1000. Further, the separate device may be
configured to supply equipment status and/or measurements such as
voltage and/or current magnitudes and/or angles along with time
stamps to the IED 1000. In certain embodiments, the information
that has been described as received from sensor component 1016 is
instead received from network interface 1002.
A monitored equipment interface 1008 may be configured to receive
status information from, and issue control instructions to a piece
of monitored equipment. Monitored equipment interface 1008 may be
configured to issue control instructions to one or more pieces of
monitored equipment. According to some embodiments, control
instructions may also be issued via network interface 1002. Control
instructions issued via network interface 1002 may be transmitted,
for example, to other distributed controllers, coordination
controllers, IEDs, or the like (not shown), which in turn may issue
the control instruction to a piece of monitored equipment.
Alternatively, the piece of monitored equipment may receive the
control instruction directly via its own network interface.
Computer-readable storage medium 1010 may be the repository of one
or more modules and/or executable instructions configured to
implement certain functions and/or methods described herein. For
example, computer-readable storage medium 1010 may include a fault
detection module 1028, which may be a repository of the modules
and/or executable instructions configured to implement the HIF
detection and protection functionalities described herein. The
distributed controller module 1028 may include, among others, a
system noise reference module 1030, a detection tuning module 1032,
a fault detection module 1034, and a protective action
implementation module 1036. The computer-readable medium 1010 may
further include a communication module 1038 and a control module
1040.
Fault detection module 1034 may be configured to perform certain
HIF detection functions described herein. In certain embodiments,
the fault detection module 1034 may be configured to identify the
occurrence of an HIF based on instantaneous interharmonic content
included in a current signal information, that may be provided, for
example, by the sensor component 1016. In certain embodiments, the
fault detection module 1034 may interface with a system noise
reference module 1030, which may store average interharmonic
content of a current signal over time. Such information may be used
by the fault detection module 1034 in differentiating interharmonic
content associated with an HIF from interharmonic content
associated with normal system noise.
In further embodiments, the fault detection module 1034 may
interface with a detection tuning module 1032 that may provide
information utilized in tuning fault detection thresholds. In
certain embodiments, such thresholds may be dynamically adapted
and/or tuned based on interharmonic content included in signals
measured by sensor component 1016 over time. A protective action
implementation module 1036 may interface with the fault detection
module 1034. Upon receiving an indication from the fault detection
module 1034 of a detected HIF event, protective action
implementation module 1036 may implement one or more protective
actions to mitigate potentially unsafe conditions and damage to an
electric power delivery system (e.g., issuing control instructions
to trip a breaker and isolate the HIF from the system).
A control module 1040 may be configured for interacting with
monitored equipment connected to distributed controller via
monitored equipment interface 1008 and/or via network interface
1002. According to some embodiments, control instructions from the
control module 1040 may be intended as control instructions for
other IEDs and/or monitored equipment located remote to IED 1000.
In some cases, control instructions may be only informative or
suggestive, meaning that the receiving IED is not obligated to
perform the control instruction. Rather, the receiving IED may use
the suggested control instruction in coordination with its own
determinations and information from other controllers to determine
whether it will perform the control instruction. In other cases
control instructions may be directive in that they are required
actions. Differentiation between informative or suggestive control
instructions and mandatory control instruction may be based on
information included with the control instruction.
A communication module 1038 may include instructions for
facilitating communication of information from IED 1000 to other
controllers and/or other components in the electric power delivery
system. The communication module 1038 may include instructions on
the formatting of communications according to a predetermined
protocol. Communication module 1038 may be configured with
subscribers to certain information, and may format message headers
according to such subscription information.
While specific embodiments and applications of the disclosure have
been illustrated and described, it is to be understood that the
disclosure is not limited to the precise configurations and
components disclosed herein. For example, the systems and methods
described herein may be applied to an industrial electric power
delivery system or an electric power delivery system implemented in
a boat or oil platform that may not include long-distance
transmission of high-voltage power. Moreover, principles described
herein may also be utilized for protecting an electrical system
from over-frequency conditions, wherein power generation would be
shed rather than load to reduce effects on the system. Accordingly,
many changes may be made to the details of the above-described
embodiments without departing from the underlying principles of
this disclosure. The scope of the present invention should,
therefore, be determined only by the following claims.
* * * * *